Ruiz, Fernando (ADNOC Onshore) | Hebish, Ayman (ADNOC Onshore) | Negoi, Adrian (ADNOC Onshore) | Al Hendi, Mohammed (ADNOC Onshore) | Hamdy, Ibrahim (ADNOC Onshore) | Nunez, Ygnacio (ADNOC Onshore) | Mandal, Vivekananda (ADNOC Onshore) | Al Samahi, Musabbeh (ADNOC Onshore) | Al Hadidy, Khaled (ADNOC Onshore) | Al Awadhi, Eman (ADNOC HQ) | El Yossef, Bassem (ADNOC HQ) | Coscia, Marco (ADNOC HQ)
This paper has the recommended procedures to be carried out in each phase: Surface, Intermediate I and II, horizontal and completion with frac string, for Unconventional Appraisal HP/HT wells across Deyab formations in Abu Dhabi (UAE), as well as the technology to be used and avoid, to drill the wells saving time and money helping to make a rentable project.
Due to the information received of the zone was scarce, in addition the first well in the area (offset well and taken as a reference) had many operational problems. The operations during drilling the next three wells in PAD # 1 were recorded, analyzed and optimized, resulting in a learning catalog for the area, saving a considered quantity of rig days with a huge impact in the budget and the most important, the exposure of the crews/people at the location was minimized to this hazard environment.
The PAD# 1 has 03 horizontal wells, the design is Heavy Casing Design, where each phase has its characteristics to be drilled and cased. The reservoir consists of 03 cl early identified formations: Jubaila, Hanifa and Tuwaiq Mountain into the range from ± 12330 ft. TVD to ± 12900 ft. TVD. Reaching the targets with horizontal wells from 16,000 ft. MD to 17,500 ft. MD.
After analyzing each section and getting the recommendations from different service companies and specialist, the changes were implemented in the next well regarding drilling fluid MW, BHA's design, bit type & design, wiper trips, slurries, trajectories, etc. taking as result drilling wells more complicate d without operational issues, in deepest formation, drilling more than 1000 ft. MD and 600 ft. TVD, and saving 3.25 MM$ and 15.2 days per well
The PAD # 1 in Deyab field, is the pioneer for the initial development of fracking in UAE. There hasn't had a drilling procedure in detail to reach the target without having issues. This new concession has been already of interest to be developed in conjunction with the National Company, so create a Drilling Learning Catalogue as add value at the moment to handover the wells is a must.
Since 1st February 2019 Total E&P UAE Unconventional Gas B.V started to operate the Diyab shale gas field in which three horizontal exploration wells had been drilled by ADNOC. Mult- stage hydraulic fracturing treatments were performed on these wells followed by long term well testing to assess the formation potential for a further development.
It was a challenging project since it was the first shale gas frac campaign in UAE where the unconventional reservoir developments are at beginning phase. Various operational problems emerged in wireline pump down, coiled tubing milling and H2S treatment operations, especially during execution in the first well. These operational issues were mainly related to equipment availability and compatibility, personnel competency, logistics support and societal concerns of environment. Corrective measures and innovative designs were conducted to solve the technical issues and improve the operation performance. Good learning curves of different operations were achieved from the first well to the third one.
The lessons learned from this hydraulic fracturing campaign are valuable experience that will be applied to the future pilot wells in Diyab field for the continuous optimization.
Out-Of-Sequence (OOS) Fracturing can potentially maximize reservoir contact and fracture conductivity/connectivity by creating fracture complexity via reducing the stress anisotropy. It is initiated by fracturing two "book-end" frac stages (Outside Fracs), followed by a ‘middle" stage (Centre Frac) between them. The Center Frac is theorized to utilize the reduced stress anisotropy to activate pre-existing failure surfaces oriented at various azimuths and dip angles, thereby connecting bi-wing fractures to planes of weakness (natural fractures/fissures/faults/joints/cleats) and resulting in a complex fracture network that enhances connectivity and fracture area within the Stimulated Reservoir Volume (SRV). OOS Fracturing can mitigate possible issues in treatments aiming at creating fracture complexity, including zipper frac (fracture tip interference and blunting inhibiting fracture extension), modified zipper frac (risks of well bashing and fractures growing asymmetrically opposite of the induced stress from prior stage in the adjacent well), simultaneous frac (middle clusters experiencing larger stress interference inhibiting their growth), and high-rate fracturing (risk of cluster erosion reducing the limited entry effect and premature screenout due to inconsistent diversions inside fractures).
Since its inception in early 2010s, OOS Fracturing has not gained considerable attention due to previously-existing operational limitations in fracturing out-of-sequence. It is reported to have been field tested in Western Siberia in 2014 with claimed well performance success. Operational limitations of the system employed in that trial is believed to have prevented its commercial development at that time. With the advent of Multicycle Sleeves and Shift-Frac-Close operation with a single Bottom-Hole Assembly to open and close sleeves, previous operational limitations of OOS Fracturing have been resolved. OOS Fracturing has since been trialed in three formations in Western Canada (2017/2018). This work analyzes the fracture treatment pressures and well performance of these trials.
Five OOS Fracturing trials in these three formations reveal that normalized 15-month/18-month production from out-of-sequence-fractured wells outperform that of sequentially-fractured offsets, with similar formation properties and treatment designs. Instantaneous Shut-In Pressures (ISIP) of Centre Frac are generally higher than that of either Outside Fracs. Breakdown pressures for Centre Fracs exhibit a mixed trend, confirming that reducing stress anisotropy could lower the breakdown gradient (based on Kirsch Equation) if rock fabric permits. Well performance and treatment pressures appear to be more sensitive to Centre Frac proppant tonnage/fluid volumes and uneven sleeve spacing.
This is the first attempt in analyzing the five OOS Fracturing trials, with encouraging well performance and operational execution in conventional reservoirs where it was deployed. Despite uneven sleeve spacing, depletion due to offset production, and less favorable geomechanical properties (high Poisson’s Ratio and low Young’s Modulus), field trials produced favorable results. True potential of non-sequential fracturing is potentially more promising in unconventional reservoirs with formation properties more conducive to complex fracture generation.
A new electronic sliding sleeve has been developed for hydraulic fracturing that combines the best features of traditional sliding sleeves and plug and perf techniques. This battery-powered electronic sliding sleeve provides the operational efficiency of sliding sleeves in an unlimited number of zones. The firmware, electrohydraulic lock, and electronics package in this new sliding sleeve help enable a range of operational functions for use in hydraulic fracturing.
Traditional sliding sleeves use a series of progressively sized balls that shift sleeves by landing on progressively sized baffles. An electronic sliding sleeve creates a monobore construction with the same inside diameter bore in each sleeve and helps enable treating of an unlimited number of zones. The electronics in the sliding sleeve helps eliminate the mechanical complexity of other monobore fracturing tools. The firmware and electronic package enable a modular approach to electronic sleeve design. Therefore, one frac sleeve chassis design can be used for many of the different types of sleeve tools in the well completion, and the firmware that drives the electronics is modified for each respective type of tool.
Using combinations of the electrohydraulic lock, electronics package, and firmware can enable the design of all the tools necessary to complete a wellbore. The standard firmware, used for a single point entry sleeve, operates by counting the correct number of frac balls. When the correct count is reached, the electrohydraulic lock is released, enabling sleeve movement or zonal isolation deployment. A modification can be made to the firmware to have the tool actuate on the next count, rather than the initial count, and delay the time at which the electrohydraulic lock is released. This type of architecture lends itself to the design of multi-entry sleeves. The sensor can also be eliminated by using the delay feature in the firmware of the electrohydraulic lock, programmed in weeks. This type of architecture also helps enable the design of a toe sleeve.
Having the ability to implement slight modifications to the components that make up the sliding sleeve enables design flexibility and modularity for all sleeve type tools necessary to complete a wellbore. This type of system architecture helps decrease operator risk and ease design constraints while performing multiple functions downhole.
Ugueto, Gustavo A. (Shell Exploration and Production) | Todea, Felix (Shell Canada Limited) | Daredia, Talib (Shell Canada Limited) | Wojtaszek, Magdalena (Shell Global Solutions International) | Huckabee, Paul T. (Shell Exploration and Production) | Reynolds, Alan (Shell Exploration and Production) | Laing, Carson (OptaSense) | Chavarria, J. Andres (OptaSense)
The use of Distributed Acoustic Sensing for Strain Fronts (DAS-SF) is gaining popularity as one of the tools to help characterize the geometries of hydraulic fracs and to assess the far-field efficiencies of stimulation operations in Unconventional Reservoirs. These strain fronts are caused by deformation of the rock during hydraulic fracture stimulation (HFS) which produces a characteristic strain signature measurable by interrogating a glass fiber in wells instrumented with a fiber optic (FO) cable cemented behind casing. This DAS application was first developed by Shell and OptaSense from datasets acquired in the Groundbirch Montney in Canada. In this paper we show examples of DAS-SF in wells stimulated for a variety of completion systems: plug-and-perforating (PnP), open hole packer sleeves (OHPS), as well as, data from a well completed via both ball-activated cemented single point entry sleeves (Ba-cSPES) and coil-tubing activated cemented single point entry sleeves (CTa-cSPES). By measuring the strain fronts during stimulation from nearby offset wells, it was observed that most stimulated stages produced far-field strain gradient responses in the monitor well. When mapped in space, the strain responses were found to agree with and confirm the dominant planar fracture geometry proposed for the Montney, with hydraulic fractures propagating in a direction perpendicular to the minimum stress. However; several unexpected and inconsistent off-azimuth events were also observed during the offset well stimulations in which the strain fronts were detected at locations already stimulated by previous stages. Through further integration and the analysis of multiple data sources, it was discovered that these strain events corresponded with stage isolation defects in the stimulated well, leading to "re-stimulation" of prior fracs and inefficient resource development. The strain front monitoring in the Montney has provided greater confidence in the planar fracture geometry hypothesis for this formation. The high resolution frac geometry information provided by DAS-SF away from the wellbore in the far-field has also enabled us to improve stage offsetting and well azimuth strategies. In addition, identifying the re-stimulation and loss of resource access that occurs with poor stage isolation also shows opportunities for improvement in future completion programs. This in turn, should allow us to optimize operational decisions to more effectively access the intended resource volumes. These datasets show how monitoring high-resolution deformation via FO combined with the integration of other data can provide high confidence insights about stimulation efficiency, frac geometry and well construction defects not available via other means.
The technical challenges imposed by tight well spacing and fracture interactions have become a focal point of recent earnings calls between investors and the leaders of several shale producers. The picture of the future is becoming clearer, and there are fewer oil wells in it. For the next several years, supplies of crude will depend on several macro factors. Some are easier to forecast than others. The upcoming event will provide the shale sector with a venue to share new learnings and approaches meant to overcome one of its greatest subsurface challenges.
Baker Hughes is still a GE company, but it has partnered with a second company for artificial intelligence expertise, C3.ai. The deal is expected to speed the integration of AI into oilfield operations by the company which also markets GE’s device analytics platform, Predix. The three largest service companies are optimistic about the rest of 2019. An assortment of sustainability initiatives shows how the oil and gas industry, leveraging its reach, diversity, and resources, is going well beyond just supplying energy to impact the world for the better. A contest where teams of college students design and build an automated drilling rig able to deal with hazardous obstacles in a test block, showed how a small change can be engineered to matter.
Baker Hughes is still a GE company, but it has partnered with a second company for artificial intelligence expertise, C3.ai. The deal is expected to speed the integration of AI into oilfield operations by the company which also markets GE’s device analytics platform, Predix. The firm hopes to remedy the cost-, labor-, and time-intensive process of executing offshore projects through deployment of “Subsea Connect,” which it says can cut project development costs by 30%. The deal would raise nearly $4 billion for GE, which plans to reduce its stake in the oilfield services company from 62.5% to at least 50.1% after the transactions. It had previously announced in June its intention to sell its stake over a 2- to 3-year period.
If you can see it, then maybe you can control it. This sums up the latest quest that the unconventional engineering community embarked upon to get a better understanding of proper well spacing and how fractures really interact. First developed as a proprietary system by a large Permian Basin operator, this hydraulic fracturing schedule exchange will be run by a data company and opened up to the entire North American shale sector. The complicated parent-child relationship in US shale fields is emerging as a turning point in the US shale revolution. One of the first executives to exploit tight oil says the issue will reverse the sector’s cumulative growth rate by 2025.
Devon Energy and its debt gets smaller, as Canadian Natural Resources adds to its huge, long-term bet on Canadian heavy and ultra-heavy crude. The technical challenges imposed by tight well spacing and fracture interactions have become a focal point of recent earnings calls between investors and the leaders of several shale producers. The picture of the future is becoming clearer, and there are fewer oil wells in it. If the shale sector’s most complex problem can be solved, it will require companies to use their wells as a team. Newly detailed field work shows that a good defense is the key to success.